1. Field of the Invention
This invention relates generally to oilfield wellbore drilling systems and more particularly to subsea drilling systems that control bottom hole pressure or equivalent circulating density during drilling of the wellbores.
2. Background of the Art
Oilfield wellbores are drilled by rotating a drill bit conveyed into the wellbore by a drill string. The drill string includes a drilling assembly (also referred to as the “bottom hole assembly” or “BHA”) that carries the drill bit. The BHA is conveyed into the wellbore by a tubing. Coiled tubing or jointed tubing is utilized to convey the drilling assembly into the wellbore. The drilling assembly sometimes includes a drilling motor or a “mud motor” that rotates the drill bit. The drilling assembly also includes a variety of sensors for taking measurements of a variety of drilling, formation and BHA parameters. A suitable drilling fluid (commonly referred to as the “mud”) is supplied or pumped from the surface down the tubing. The drilling fluid drives the mud motor and then it discharges at the bottom of the drill bit. The drilling fluid returns uphole via the annulus between the drill string and the wellbore and carries with it pieces of formation (commonly referred to as the “cuttings”) cut or produced by the drill bit in drilling the wellbore.
For drilling wellbores under water (referred to in the industry as “offshore” or “subsea” drilling) tubing is provided at the surface work station (located on a vessel or platform). One or more tubing injectors or rigs are used to move the tubing into and out of the wellbore. In sub-sea riser-type drilling, a riser, which is formed by joining sections of casing or pipe, is deployed between the drilling vessel and the wellhead equipment at the sea bottom and is utilized to guide the tubing to the wellhead. The riser also serves as a conduit for fluid returning from the wellhead to the vessel at sea surface.
During drilling, the drilling operator attempts to carefully control the fluid density at the surface so as to prevent an overburdened condition in the wellbore. In other words, the operator maintains the hydrostatic pressure of the drilling fluid in the wellbore above the formation or pore pressure to avoid well blow-out. The density of the drilling fluid and the fluid flow rate largely determine the effectiveness of the drilling fluid to carry the cuttings to the surface. One important downhole parameter during drilling is the bottomhole pressure, which is effectively the equivalent circulating density (“ECD”) of the fluid at the wellbore bottom.
This term, ECD, describes the condition that exists when the drilling mud in the well is circulated. ECD is the friction pressure caused by the fluid circulating through the annulus of the open hole and the casing(s) on its way back to the surface. This causes an increase in the pressure profile along this path that is different from the pressure profile when the well is in a static condition (i.e., not circulating). In addition to the increase in pressure while circulating, there is an additional increase in pressure while drilling due to the introduction of drill solids into the fluid. This pressure increase along the annulus of the well can negatively impact drilling operations by fracturing the formation at the shoe of the last casing. This can reduce the amount of hole that can be drilled before having to set an additional casing. In addition, the rate of circulation that can be achieved is also limited. Due to this circulating pressure increase, the ability to clean the hole is severely restricted. This condition is exacerbated when drilling an offshore well. In offshore wells, the difference between the fracture pressures in the shallow sections of the well and the pore pressures of the deeper sections is considerably smaller compared to on-shore wellbores. This is due to the seawater gradient versus the gradient that would exist if there were soil overburden for the same depth.
In order to be able to drill a well of this type to a total wellbore depth at a subsea location, the bottom hole ECD must be reduced or controlled. One approach to do so is to use a mud filled riser to form a subsea fluid circulation system utilizing the tubing, BHA, the annulus between the tubing and the wellbore and the mud filled riser, and then inject gas (or some other low density liquid) in the primary drilling fluid (typically in the annulus adjacent the BHA) to reduce the density of fluid downstream (i.e., in the remainder of the fluid circulation system). This so-called “dual density” approach is often referred to as drilling with compressible fluids.
Another method for changing the density gradient in a deepwater return fluid path has been proposed. This approach proposes to use a tank, such as an elastic bag, at the sea floor for receiving return fluid from the wellbore annulus and holding it at the hydrostatic pressure of the water at the sea floor. Independent of the flow in the annulus, a separate return line connected to the sea floor storage tank and a subsea lifting pump delivers the return fluid to the surface. Although this technique (which is referred to as “dual gradient” drilling) would use a single fluid, it would also require a discontinuity in the hydraulic gradient line between the sea floor storage tank and the subsea lifting pump. This requires close monitoring and control of the pressure at the subsea storage tank, subsea hydrostatic water pressure, subsea lifting pump operation and the surface pump delivering drilling fluids under pressure into the tubing for flow downhole. The level of complexity of the required subsea instrumentation and controls as well as the difficulty of deployment of the system has delayed the commercial application of the “dual gradient” system.
Another approach is described in U.S. patent application Ser. No. 09/353,275, filed on Jul. 14, 1999 and assigned to the assignee of the present application. The U.S. patent application Ser. No. 09/353,275 is incorporated herein by reference in its entirety. One embodiment of this application describes a riserless system wherein a centrifugal pump in a separate return line controls the fluid flow to the surface and thus the equivalent circulating density.
The present invention provides a wellbore system wherein equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in the returning fluid path of a riser utilizing an active differential pressure device, such as a centrifugal pump or turbine, located adjacent to the riser. The fluid is then returned into the riser above the restriction. The present invention also provides a dual gradient subsea drilling system wherein equivalent circulating density is controlled by controllably bypassing the returning fluid about a restriction in a riser by utilizing an active differential pressure device, such as a centrifugal pump or turbine located some distance above the sea bed. The present systems are relatively easy to incorporate in new and existing systems.